Rapid Shift

Clean energy portfolios are economically attractive alternatives new gas-fired power plants, beating operating costs of efficient gas-fired power plants. How do we maximally use least-cost portfolios of distributed energy resources (DERs) to complement traditional electric grid infrastructure or to defer or avoid investments in it?

Clean energy portfolios are economically attractive alternatives new gas-fired power plants, beating operating costs of efficient gas-fired power plants. How do we maximally use least-cost portfolios of distributed energy resources (DERs) to complement traditional electric grid infrastructure or to defer or avoid investments in it?

How do we maximally use least-cost portfolios of distributed energy resources (DERs) to complement traditional electric grid infrastructure or to defer or avoid investments in it? These combinations, also known as clean energy portfolios (CEPs), consist of resources like utility-scale and distributed wind and solar generation, battery energy storage, energy efficiency, and demand-response technologies used in place of new power plants or transmission and distribution infrastructure.

In a recent report, The Economics of Clean Energy Portfolios, RMI showed that new-built CEPs are already an economically attractive alternative to new gas-fired power plants in most cases and are likely to beat just the operating costs of efficient gas-fired power plants within the next two decades. Four teams came to Accelerator 2018 to work on distributed grid infrastructure projects. These are their stories.

Modeling Clean Energy Portfolios

One of the fundamental questions about how to plan for distributed grid infrastructure is how utilities should model it. The default has been to calculate how much generation capacity the grid will need to meet demand in the coming years, and then simply plan for a thermal power plant—coal, nuclear, or natural gas—to provide that capacity, knowing that such a plant will also provide (more than) adequate grid services. It’s now clear that less-expensive combinations of renewables and DERs can often provide the same grid benefits as a thermal power plant, but there’s no good way to include these attributes in the planning process—even industry-standard modeling software doesn’t have a good way to include DERs.

The Accelerator team that tackled this problem included representatives from utilities in Tennessee and California, DER technology providers, and nonprofit organizations. Their common goal was to explore how the resources that make up CEPs can supplant new power plants (in practice, this almost always means new gas-fired plants) and how utilities can change the planning process to include all options to enable an informed choice.

The difficulty in comparing DERs to power plants means utilities risk making an uneconomic choice and potentially stranding assets like power plants that are still within their operating lives but whose operating costs make them uncompetitive. And it makes it hard for outside advocates for clean energy to propose alternatives to new fossil-fueled power plants, on top of the general lack of access to data that often frustrates such environmental advocacy in the electric industry. These issues are not theoretical; there are several cases today where gas-plant projects amounting to billions of dollars of investment are on hold while regulators try to determine whether renewable energy and storage technologies might be better options.

The question, “what is the basis for comparing these things?” leads to questions that are tricky in their own right, such as if CEPs need to do exactly what a gas-fired plant would do. Ideally, a utility would define how much peak generation capacity, ramping capacity, frequency regulation capacity, and so forth that new resources need to have. But, explained the team’s facilitator, RMI manager Mike Henchen, “New gas plants don’t match exactly what a utility needs.” They typically oversupply ramping and frequency regulation, among other grid services. “So matching a gas plant with a clean energy portfolio exactly would overinvest.”

Another tricky question is how to handle the values that CEPs provide that gas plants do not, but that are difficult to assign a dollar value to. For instance, placing renewable energy generation and battery energy storage resources across the distribution grid reduces the need for added transmission and distribution infrastructure that a new, centralized power plant would require. But it’s difficult to model exactly how many substations and how many miles of lines would be avoided with DERs because so many factors, like the changing scale and location of demand, must be estimated over so many years.

The team conceived of near-term and long-term solutions to these planning problems. In the near term, they found ways to take existing planning processes and plug different portfolios of resources into them, however inelegantly. This approach has immediate value while not changing the entire utility planning process, and importantly, it can be piloted right away.

For the long term, the team discussed an attribute-based approach in which a utility establishes what increments of different attributes it will need, year by year, over the next 10 or 20 years, and then judges whether a CEP or a power plant would be the least-cost source of those attributes. This would take into account the dynamic, incremental nature of DER investment, instead of treating DERs like one-off power plant investments. Some utilities are piloting this attribute-based planning approach in limited, small-scale experiments. One of the most advanced is the Preferred Resources Pilot, a project of one of the team members, Southern California Edison. More than 100 MW of DERs are expected to be operational by the end of the year in Orange County, California.

But while the team broadly aligned on a shift to attribute-based modeling, accounting for the extra value of CEPs remains a tough nut to crack. For the foreseeable future, CEPs will retain the handicap of not having their full value included in cost-benefit comparisons with new power plants. Still, with the goodwill and effort of stakeholders like the Accelerator team, that problem should be solved soon.

Planning for High Renewables Penetration

A team from New Mexico came to Accelerator to focus on a common problem: how to integrate large quantities of renewable energy onto the electric grid. It is possible to achieve a system that gets the majority of its energy from renewables, and such systems can be more reliable than grids that rely predominantly on fossil fuels. But the transition can be tricky. Representatives of New Mexico’s state and local governments, nonprofits, and the investor-owned utility Public Service Company of New Mexico (PNM) wrestled at Accelerator with how to plan for and achieve that transition.

PNM has already announced an integrated resource plan that goes beyond New Mexico’s renewable portfolio standard of 20 percent by 2020 (PNM already exceeds the current standard of 15 percent) by adding wind, solar, and geothermal supply, together with energy efficiency and demand response. The utility also plans to retire its coal generation fleet entirely by 2031. PNM is considering an eventual transition to 100 percent renewable generation, as are stakeholder groups across the state. But increasing the percentage of renewables generation above a threshold of about 30 percent raises difficult operational issues.

The team’s facilitator, Kendall Ernst, a senior associate at RMI, said that “all the different parties, really the team as a whole, had a very similar vision of what the future could be.” When they discussed their vision of what PNM’s grid would look like in 2050, they agreed that it could be clean, renewable, supplied by diverse resources, and low cost. But how to get there? And how quickly is it feasible to achieve intermediate goals, like 50 percent penetration? They found that these steps are difficult to plan.

To begin with, there are regulatory issues that complicate adding additional renewables: regulations mandate choosing the least-cost option. Using natural gas-fired power can be less expensive than adding more solar capacity. And there are rules about avoiding duplicative resources that complicate adding solar capacity that only yields power during part of the day; it can be construed as being duplicative with existing resources that can operate around the clock. Storage would be an effective solution to that obstacle, but it is difficult to say how inexpensive storage will be in 2030, 2040, or 2050. The economic value of adding gas-fired power plants depends, among other variables, on the future cost of storage. In the long term, the falling price of renewables and storage increasingly will challenge the economics of gas-fired generation, as RMI’s Economics of Clean Energy Portfolios report showed. But the medium term is where the tough questions lie.

Those medium-term questions include: What mix of resources is right for each year? What will be the cost of storage and other distributed energy resources? Will investors and developers that today fund development of fossil fuel assets that are being built for tomorrow receive acceptable returns as the grid evolves? And what makes the most sense to use as a bridge resource between the present and the clean, renewable future? The team made progress on finding how to answer these questions for New Mexico, considering the proper role of governments and advocates in setting such intermediate goals, and they discussed how scenario planning can best be accomplished. It is efforts like theirs that may help solve how to handle the clean-energy transition.

Optimizing Buildings to Interact with the Grid

Another team grappling with integrating renewables into the grid was the GridOptimal Initiative, which focused on how buildings can be made smarter and more responsive to the grid by using distributed renewables and automated management like smart controls and demand response. GridOptimal is a joint effort by the New Buildings Institute and the US Green Building Council to create a rating system that provides standardized metrics, tools, and guidance to improve building-grid interactions, and to help both building owners and utilities shape the value and opportunity of grid-integrated buildings. Representatives from utilities including Sacramento Municipal Utility District and Austin Energy were there, as well as other stakeholders. Grid-integrated buildings, supported by initiatives like GridOptimal, present an exciting opportunity to go beyond net-zero energy structures and provide valuable benefits to the electric grid while also earning money for building owners. A full discussion of this team’s exciting topic is available here.

Planning for DERs when You Don’t Have To

A team composed largely of representatives of Southern Company, an American gas and electric utility holding company based in the southern United States, came to Accelerator because they saw the rapidly dropping price of DERs, and wanted to plan for the adoption of DERs as a non-wires alternative in the absence of a regulatory mandate to do so. While most of the states where Southern Company serves customers don’t have any renewable portfolio standards, including Mississippi, Alabama, Florida, and Georgia, where it is headquartered, Georgia Power has developed one of the largest voluntary solar portfolios in the nation.

Southern Company’s utilities in the southeast have already deployed or committed to over 2,000 MW of renewable energy and want to continue to expand their utilization of renewable energy to meet their customers’ expectations. The declining price and improvements in technology could make DERs attractive to provide the best overall value to Southern Company customers. Furthermore, Southern Company has very large customers in businesses like data storage that need very high levels of reliability, which energy storage can be vital to providing.

As the holding company, it is Southern Company’s role to do research and development and establish best practices to guide its subsidiaries as they set policies with each state’s regulators and each utility’s customers. And the company is aware that business as usual won’t be best practice for long. Steps must be taken now to develop the tools and processes for integrating DERs as a non-wires alternative and modernize the grid to meet Southern Company’s carbon reduction strategy.

The team, which included representatives from nonprofits and technology providers, came to a good understanding of what non-wires alternatives made sense for them. They discussed how distributed generation could provide even better service by increasing resilience, reliability, and power quality. Part of Southern Company’s service area is an island in the Gulf of Mexico that is often impacted by hurricanes, so the resilience benefits of storage would be particularly excellent there. And placing generation and storage at the distribution edge wouldn’t just help with things like voltage support, it would also avoid some investment in transmission and distribution infrastructure. Battery prices are declining, and storage could soon be an economically optimal solution in more and more places. Investments in DERs could also help Southern Company reach its decarbonization goals.

Because Southern Company operates 11 regulated utilities serving 9 million customers in nine states, there are a lot of stakeholders to bring on board to effect company-wide change. The team’s facilitator, RMI senior associate Kevin Brehm, explained that the team “thought about how to approach key decision makers so that they can update the company’s planning processes to include non-wires alternatives.” They determined that the first step was to draft a paper to lay out the business case for adding a portfolio of DERs across the company. This will be the basis for an internal effort to consider and weigh the scale and complexity of the changes they might propose.

Technology and the electric industry are changing as the clean energy revolution progresses, and large players like Southern Company are on the front lines. Proactive planning like theirs stands to benefit the company, the grid, and its customers.

All 13 teams at e–Lab Accelerator this year came to work on issues at the grid edge, and the four teams highlighted in this three-part blog series made progress on different aspects of how distributed grid infrastructure can make a difference there. Such infrastructure holds great promise, and we look forward to hearing how its development furthers the energy revolution.

The work of the other two teams is discussed in other blogs. The first blog in this series is available here, and the second here.